Conventional oil recovery involves drilling a well and pumping a mixture of oil and water from the well. Oil is separated from the water, and the water is usually injected into a sub-surface formation. Conventional recovery works well for low viscosity oil. However, conventional oil recovery processes do not work well for higher viscosity, or heavy, oil.
Enhanced Oil Recovery processes employ thermal methods to improve the recovery of heavy oils from sub-surface reservoirs. The injection of steam into heavy oil bearing formations is a widely practiced enhanced oil recovery method. Typically, several tons of steam are required for each ton of oil recovered. Steam heats the oil in the reservoir, which reduces the viscosity of the oil and allows the oil to flow to a collection well. Steam condenses and mixes with the oil, the condensed steam being called produced water. The mixture of oil and produced water that flows to the collection well is pumped to the surface. Oil is separated from the produced water by conventional processes employed in conventional oil recovery operations.
For economic and environmental reasons it is desirable to recycle the produced water used in steam injection enhanced oil recovery. This is accomplished by treating the produced water, producing a feedwater, and directing the treated feedwater to a steam generator or boiler which produces steam. The complete water cycle includes the steps of:                injecting the steam into an oil bearing formation,        condensing the steam to heat the oil whereupon the condensed steam mixes with the oil to form an oil-water mixture,        collecting the oil-water mixture in a well,        pumping the oil-water mixture to the surface,        separating the oil from the oil-water mixture to yield produced water,        treating the produced water so that it becomes the steam generator or boiler feedwater, and        converting the feedwater into steam that has a quality suitable for injecting into the oil bearing formation.        
Treating the produced water to prepare feed water for steam generation is challenging. It is known to chemically treat the produced water and subject the produced water to an evaporation process to form distillate for steam generation feed water. In particular, it is known to use an evaporator and mechanical vapor compressor to produce the distillate. However, the produced water typically contains significant amounts of silica-based compounds. These silica-based compounds will tend to foul evaporator and other process surfaces by scaling or deposition of silica on the surfaces. These scales reduce the conductivity of heat transfer elements in the equipment and thus reduce the efficiency of evaporation and steam generation. To prevent or retard fouling of the evaporator heat transfer surfaces from silica-based scaling, the pH of the feed to the evaporator is conventionally raised to maintain the solubility of silica.
There are drawbacks and disadvantages to the current processes. The addition of caustic to raise the pH represents a significant operating cost. The high concentration of caustic is typically not desirable in waste streams. Additionally, while the mechanical vapor compression evaporator recovers approximately 95% of the water from the produced water, the remaining concentrate stream is difficult to process. The pH of the remaining concentrate stream is usually higher than 12. Neutralizing the stream causes the precipitation of solids, and these solids are very difficult to separate from the aqueous solution. The neutralization process is also known to sometimes release gases such as hydrogen sulfide. These systems tend to be expensive to operate and costly to maintain. Moreover, produced water often includes significant amounts of calcium and magnesium which contribute to hardness. The higher pH promotes the precipitation of hardness components, calcium and magnesium. This creates the potential for hardness scaling of the evaporator heat transfer surfaces if not controlled. The scaling threat from hardness can be reduced by chemical addition in the form of a dispersant. The dispersant suspends the particles so that they do not stick and foul evaporator surfaces. At this time, it does not appear that it has been determined how much hardness can be controlled using a dispersant since few existing heavy oil recovery operating systems have very low hardness in the produced water. However, it is anticipated that in future heavy oil recovery processes that the produced water will include higher brackish water makeup and that the concentration of hardness in the produced water will be significant. The higher pH processes with dispersant may not be effective in produced water having a significant hardness concentration.
In addition, heavy oil recovery processes utilizing evaporators produce a concentrated brine and appropriately disposing of this concentrated brine is sometimes problematic. This is particularly true with high pH brine. High pH brine requires that the silica levels be reduced to allow disposal and ensure that silica precipitants will not plug the disposal well. This treatment process involves large amounts of acid as all of the caustic added to increase the pH must now be neutralized. As the pH is reduced, silica gels form which must be removed from the brine. Operating experience is limited for this brine treatment process, but frequent plugging of equipment and lines has been reported. If the high pH brine is to be deep well injected, the treatment process is difficult, costly and unreliable. There is an alternative option to deep well injection and that is salt cavern disposal. However, this option is significantly more expensive than deep well injection.
Therefore, there is a need in heavy oil recovery processes for a more cost-effective evaporation system for treating produced water and producing a relatively pure feedwater stream for a steam generation system.